Downhole Artificial Lift Compressor for Improving Unconventional Oil and Gas Recovery

ABSTRACT

A high-speed downhole motor-driven artificial-lift gas compressor assembly comprising an aerodynamic, gas-bearing supported, multi-stage centrifugal compressor is deployed downhole to work with other components such as electric submersible pumps and separators disposed in a multizone reservoir. Water may be injected into an injection water zone and hydrocarbons allowed to escape from a hydrocarbon producing zone to the surface. Compressed gas may be introduced into an annulus between a casing and tubing and directed into an injection gas zone. In addition, gas being produced in the hydrocarbon producing zone may flow back through the annulus between the casing and tubing or through one or more water separators and/or gas separators into the high-speed downhole motor-driven artificial-lift gas compressor assembly and, once compressed, exit the high-speed downhole motor-driven artificial-lift gas compressor assembly and routed back to the injection gas zone. Thus, water and gas may be separated from the fluid flows and injected back downhole or, alternatively, water may be separated from the fluid flows and hydrocarbons such as oil and/or gas allowed to flow to the surface.

RELATION TO OTHER APPLICATIONS

This application claims priority through U.S. Provisional Application62/827,683 filed on Apr. 1, 2019.

BACKGROUND

Ultimate recovery from unconventional reservoirs still has a long way tocome. Unconventional reservoirs are described as wells produced in lowpermeability (tight) formations composed as tight sands, carbonates,coal, and shale. Although tight gas and coal bed natural gas arevaluable sources of energy, wells produced from low permeability shaleformations (shale gas) promise over 1,744 trillion cubic feet (tcf) ofrecoverable gas, which comprises the majority of unconventional oil andgas reserves. Shale is a sedimentary rock comprised of consolidatedclay-sized particles. These are deposited as mud along with organicmatter such as plants, animal remains, and the like. The end result is arock formation with a permeability of 0.01-0.00001 millidarcies. In itsnatural state, this permeability prevents the migration of oil and gaswithin the formation over periods less than geologic expanses of time,and was initially thought to be uneconomical to produce. With theadvancement of horizontal drilling and multistage hydraulic fracturingin the late 1990s, shale oil and gas reservoirs became economical toproduce.

As compared to conventional oil wells, many shale gas wells arecharacterized by a higher gas-oil ratio (GOR). Although there are somebenefits to producing high GOR wells, there are also some drawbacks. Inshale gas, the migration of oil through the rock fractures is primarilydue to Poiseuille flow of the shale gas, i.e. pressure-driven flow ofgas carries the oil when equalizing pressure. The pressure driving thisflow is due to the natural pressure gradient that is created by“uncorking” the well at the surface, causing the less dense gas toevacuate the reservoir and rise up the well bore. When this processcarries substantial liquid condensates, the specific gravity of themixture in the well-bore creates a fluid column that pushes back on thereservoir; thus, we can define the bottom-hole flowing pressure (BHFP)as the pressure at the bottom of a flowing well, and the flowing tubinghead pressure (FTHP) as the pressure at the surface of a flowing well.

While gas gathering systems at the surface often operate at 40-100 psi,wellhead compression can be employed to reduce this FTHP, also improvingthe minimum BHFP and ultimately reducing well abandonment pressureresulting in higher recovery and increased reserves. At the surface, afacility can at most draw down the well by pulling a vacuum fromatmospheric pressure. While this technology can help reduce theabandonment pressure, the hydrostatic pressure gradient in the tubing isstill tied to the specific gravity of the fluid in the tubing, and canonly be altered moderately by well-head compression. Low gas pressures,temperatures, and velocities in the tubing will result in liquid dropoutin the tubing, which can become suspended in the tubing. This liquidloading impedes production from the well and impact its economicviability, resulting in abandonment. Ultimately, the abandonmentpressure depends greatly on GOR, water production, well depth, etc. andis likely several hundred psi.

In many cases, the specific gravity of the fluid in the tubing isdecreased by implementing artificial gas lift. Artificial lift describesthe process of compressing dry gas and inserting it into the annulus.The dry gas passes down the annulus and mixes with the oil in theproduction zone of the tubing. This reduces the density of the fluid inthe tubing, thus decreasing the BHFP. This process requires access togas, surface power and compression equipment, and can be quite costly.Ultimately, this process is quite effective, and is often economical forwells whose production has been impeded by poor natural tubing flow.

Another option that has been proposed to attain better control of highGOR production is downhole gas compression. This concept is not new butits application to unconventional oil-and-gas is still in the earlystages of development. While promising, continued development of thistechnology is likely required for successful implementation in thefield. Potential issues with a downhole application include multiplechallenges associated with multiphase compression (variability inperformance, reliability, and mechanical loads), low specific loadcapacity of magnetic bearings, changing aerodynamic requirements fromreservoir maturation, overall system complexity and cost, and autonomoustool installation.

FIGURES

Various figures are included herein which illustrate aspects ofembodiments of the disclosed inventions.

FIG. 1 is a schematic view of an embodiment of the system illustrating agas lift separator, gas compressor, electric motor, and pump;

FIG. 2 is a schematic view of an embodiment of the inventionillustrating a well installation with a downhole fluid separator, ESP,electric motor and compressor;

FIG. 3 is a view in partial perspective of an exemplary compressor andturbine assembly; and

FIG. 4 is a cutaway view illustrating interior components of anexemplary compressor assembly.

DESCRIPTION OF EXEMPLARY EMBODIMENTS

In a first embodiment, referring generally to FIG. 3, compressorassembly 1, which is also referred to as a high-speed downholemotor-driven artificial-lift gas compressor assembly, comprises housing10; one or more aerodynamic, gas-bearing supported, multi-stagecentrifugal compressors 11 comprising a predetermined set of gas filmbearings 12 disposed at least partially within housing 10; and one ormore high-speed electric motor drives 21 disposed at least partiallywithin housing 10 and operatively connected to aerodynamically designed,gas-bearing supported, multi-stage centrifugal compressor 11. Compressorassembly 1 is typically designed to be deployed in casing or well 100(FIG. 2) such as a conventional reservoir or an unconventionalreservoir, e.g. a gas reservoir, a gas condensate reservoir, or an oilreservoir with associated gas production.

Housing 10 is further typically configured to be deployable within a 4.5inch casing but the casing can be as small as around 3.5 inches orlarger than 4.5 inches.

Referring additionally to FIG. 4, compressor 11 typically comprisesbetween 2 and 4 compression stages (two are illustrated) operating ataround 40000 to around 120000 rpm. In embodiments, compressor 1comprises impeller 13 which comprises impeller tip 14, generally havinga diameter of between around 65 mm to around 68 mm.

In embodiments aerodynamically designed, gas-bearing supported,multi-stage centrifugal compressor 11 comprises turbine 20 which maycomprise a hybrid gas turbine comprising a heat transfer technologyoptimized for high cycle efficiency of recuperation, intercooling, orturbine blade cooling over a range of operating conditions typical of aload following demand at a compressor station.

In embodiments, compressor 11 is configured to be powered with a turbocharger which may be powered with a high-pressure gas source.

In certain embodiments, referring additionally to FIG. 2, high-speeddownhole motor-driven artificial-lift gas compressor 11 is adapted to beused in conjunction with one or more downhole separators 32,33 andelectrical submersible pump (ESP) 30 configured to reduce gas blockageor gas lockout and improve efficiency. In these embodiments, compressor11 is further typically adapted to allow ESP 30 to be effectivelyoperated in hydrocarbon well 100 with gas production through apredetermined set of ranges of gas/oil ratio.

Referring additionally to FIG. 4, the aerodynamic design is configuredto ensure that compressor 11 achieves a predetermined set of head riseand flow characteristics desired at a target operating point. Inembodiments, the aerodynamic design comprises a 0-D or a 1-D impellerdesign. In certain embodiments, the aerodynamic design further impeller13, collector 14, diffuser 15, return channel 16, gas bearings 17,turbine nozzles 18, and turbine 19 which may comprise a radial, axial,or mixed flow geometry.

High speed electric motor 21 may comprise a plurality of 2-pole motorsarranged in series.

Referring back to FIG. 2, in a typical system, tubing 103 is deployedwithin casing 101 and compressor assembly 1 deployed within tubing 103.Umbilical 104, which may comprise an electrical pathway or otherwise bean electrical cable, may be deployed to supply electrical power asneeded to various components discussed herein above.

In the operation of exemplary methods, referring back to FIG. 2 and FIG.3, lifting a hydrocarbon from a hydrocarbon well using compressorassembly 1 comprises deploying compressor assembly 1, which is asdescribed above, in hydrocarbon well 100 such as in casing 101. Oncedeployed, high-speed downhole motor-driven artificial-lift gascompressor 11 is used to reduce pressure in reservoir 120 which isexposed to hydrocarbon well 100 and hydrocarbon allowed to flow fromreservoir 120 to surface 130 at the reduced pressure.

In embodiments, electric submersible pump (ESP) 30 may be present orotherwise deployed in hydrocarbon well 100 and operatively connected tohigh-speed downhole motor-driven artificial-lift gas compressor 11. Onceconnected, ESP 30 may then be used to aid with recovery of hydrocarbonsfrom hydrocarbon well 100.

In certain embodiments, high-speed downhole motor-driven artificial-liftgas compressor 11 may be reconfigured with one or more gas and waterseparators 32,33. In these embodiments, electric submersible pump (ESP)30 may be deployed and used to inject water downhole into a water zoneor waterflood zones to increase production and reserves. This can resultin very little water being produced to the surface requiring waterdisposal. For areas where gas sales are not available, ESP 30 may beused to inject both water and gas downhole, which may reduce a need forsurface water handling and disposal and gas injection.

As illustrated in FIG. 2, tubing 103 and/or casing 101 are exposed toreservoir 120. Multiple zones may exist in reservoir 120, e.g. injectiongas zone 121, hydrocarbon producing zone 122 which may comprise oiland/or gas, injection water zone 123 which may comprise water, or thelike, or a combination thereof. Water is injected into injection waterzone 123 and hydrocarbons escape from hydrocarbon producing zone 122back into casing 101 and/or tubing 103. Compressed gas may be introducedinto an annulus between casing 101 and tubing 103 and directed intoinjection gas zone 121, such as through packer 105. In addition, gasbeing produced in hydrocarbon producing zone 122 may flow back throughthe annulus between casing 101 and tubing 103 or through water separator33 and gas separator 32 into compressor assembly 1 such as at intake106. Once compressed, gas can exit compressor assembly 1 and routed backto injection gas zone 121 such as via compressed gas ports 107. Desiredhydrocarbons such as oil and/or gas can pass through interior 108 backto the surface. In this manner, water and gas may be separated from thefluid flows and injected back downhole or, alternatively, water may beseparated from the fluid flows and hydrocarbons such as oil and/or gasallowed to flow to the surface. This may reduce a need for surface waterhandling and disposal and gas injection.

The foregoing disclosure and description of the inventions areillustrative and explanatory. Various changes in the size, shape, andmaterials, as well as in the details of the illustrative constructionand/or an illustrative method may be made without departing from thespirit of the invention.

We claim:
 1. A high-speed downhole motor-driven artificial-lift gascompressor assembly, comprising a. a housing; b. an aerodynamic,gas-bearing supported, multi-stage centrifugal compressor comprising apredetermined set of gas film bearings disposed at least partiallywithin the housing, the aerodynamic design configured to ensure that thecompressor achieves a predetermined set of head rise and flowcharacteristics desired at a target operating point; and c. a high-speedelectric motor drive disposed at least partially within the housing andoperatively connected to the aerodynamically designed, gas-bearingsupported, multi-stage centrifugal compressor.
 2. The high-speeddownhole motor-driven artificial-lift gas compressor assembly of claim1, wherein the compressor comprises between 2 and 4 compression stages.3. The high-speed downhole motor-driven artificial-lift gas compressorassembly of claim 1, wherein the compression stages operate at around40000 to around 120000 rpm.
 4. The high-speed downhole motor-drivenartificial-lift gas compressor assembly of claim 1, wherein thecompressor comprises an impeller.
 5. The high-speed downholemotor-driven artificial-lift gas compressor assembly of claim 4, whereinthe impeller comprises an impeller tip having a diameter of betweenaround 65 mm to around 68 mm.
 6. The high-speed downhole motor-drivenartificial-lift gas compressor assembly of claim 1, wherein theaerodynamic design comprises a 0-D or a 1-D impeller design.
 7. Thehigh-speed downhole motor-driven artificial-lift gas compressor assemblyof claim 1, wherein the aerodynamic design further comprises: a. adiffuser geometry; b. an inlet guide vane (IGV); and c. a collector. 8.The high-speed downhole motor-driven artificial-lift gas compressorassembly of claim 1, wherein the housing is further configured to bedeployable within a casing comprising an inner diameter of around 3.5inches to around 4.5 inches.
 9. The high-speed downhole motor-drivenartificial-lift gas compressor assembly of claim 1, wherein thehigh-speed electric motor comprises a plurality of 2-pole motorsarranged in series.
 10. The high-speed downhole motor-drivenartificial-lift gas compressor assembly of claim 1, wherein theaerodynamically designed, gas-bearing supported, multi-stage centrifugalcompressor comprises a turbine.
 11. The high-speed downhole motor-drivenartificial-lift gas compressor assembly of claim 10, wherein the turbinecomprises a hybrid gas turbine comprising a heat transfer technologyoptimized for high cycle efficiency of recuperation, intercooling, orturbine blade cooling over a range of operating conditions typical of aload following demand at a compressor station.
 12. The high-speeddownhole motor-driven artificial-lift gas compressor assembly of claim1, wherein the compressor is configured to be powered with a turbocharger powered with a high-pressure gas source.
 13. The high-speeddownhole motor-driven artificial-lift gas compressor assembly of claim1, wherein the reservoir comprises a conventional reservoir or anunconventional reservoir.
 14. The high-speed downhole motor-drivenartificial-lift gas compressor assembly of claim 1, wherein thereservoir comprises a gas reservoir, a gas condensate reservoir, or anoil reservoir with associated gas production.
 15. The high-speeddownhole motor-driven artificial-lift gas compressor assembly of claim1, wherein the high-speed downhole motor-driven artificial-lift gascompressor is adapted to be used in conjunction with a downholeseparator and an Electrical Submersible Pump (ESP) configured to reducegas blockage or gas lockout and improve efficiency.
 16. The high-speeddownhole motor-driven artificial-lift gas compressor assembly of claim15, wherein the high-speed downhole motor-driven artificial-lift gascompressor is further adapted to allow the ESP to be effectivelyoperated in a hydrocarbon well with gas production through apredetermined set of ranges of gas oil ratio.
 17. A method of lifting ahydrocarbon from a hydrocarbon well using a high-speed downholemotor-driven artificial-lift gas compressor assembly comprising ahousing, an aerodynamic, gas-bearing supported, multi-stage centrifugalcompressor comprising a predetermined set of gas film bearings disposedat least partially within the housing, the aerodynamic design configuredto ensure that the compressor achieves a predetermined set of head riseand flow characteristics desired at a target operating point, and ahigh-speed electric motor drive disposed at least partially within thehousing and operatively connected to the aerodynamically designed,gas-bearing supported, multi-stage centrifugal compressor, the methodcomprising: a. deploying the high-speed downhole motor-drivenartificial-lift gas compressor assembly in a hydrocarbon well; b. usingthe high-speed downhole motor-driven artificial-lift gas compressorassembly to reduce pressure in a reservoir exposed to the hydrocarbonwell; and c. allowing the hydrocarbon to flow from the reservoir to thesurface at the reduced pressure.
 18. The method of claim 17, further,wherein the high-speed downhole motor-driven artificial-lift gascompressor assembly is deployed within a casing.
 19. The method of claim17, further comprising: a. deploying an electric submersible pump (ESP)in the hydrocarbon well; b. operatively connecting the ESP to thehigh-speed downhole motor-driven artificial-lift gas compressorassembly; and c. using the ESP to aid with recovery of hydrocarbons fromthe hydrocarbon well.
 20. The method of claim 19, further comprising: a.reconfiguring the high-speed downhole motor-driven artificial-lift gascompressor assembly with a gas and water separator; b. deploying anelectric submersible pump (ESP); c. using the ESP to inject waterdownhole into a water zone or waterflood zones to increase productionand reserves.
 21. The method of claim 19, further comprising: a. forareas where gas sales are not available, reconfiguring the high-speeddownhole motor-driven artificial-lift gas compressor assembly with a gasand water separator; b. deploying an electric submersible pump (ESP); c.using the ESP to inject both water and gas downhole.